1. Field of the Invention
The present invention relates generally to drilling a subterranean borehole and, more specifically, to protecting gage trimmers located adjacent to the gage of a drill bit by way of protective structures. The method and apparatus of the present invention may effect such protection for gage trimmers during drilling and/or during rotation within a casing, i.e., when changing a drilling fluid.
2. State of the Art
Fixed cutter rotary drill bits for drilling oil, gas, and geothermal wells, and other similar uses typically comprise a solid metal or composite matrix metal body having a lower cutting face region and an upper shank region for connection to the bottom hole assembly of a drill string formed of conventional jointed tubular members, which are then rotated as a single unit by a rotary table, top drive, drilling rig, or downhole motor, alone or in combination with one another. Alternatively, rotary drill bits may be attached to a bottomhole assembly including a downhole motor assembly which is in turn connected to essentially continuous tubing, also referred to as coiled, or reeled, tubing wherein the downhole motor assembly rotates the drill bit. Typically, the bit body has one or more internal passages for introducing drilling fluid, or mud, to the cutting face of the drill bit to cool cutters provided on the face of the drill bit and to facilitate formation chip and formation fines removal. The sides of the drill bit typically include a plurality of radially extending blades that have an outermost surface of a substantially constant diameter and generally parallel to the central longitudinal axis of the drill bit, commonly known as gage pads. The gage pads generally contact the wall of the bore hole being drilled in order to support and provide guidance of the drill bit as it advances along a desired cutting path, or trajectory.
As known within the art, blades provided on a given drill bit may be selected to be provided with outwardly extending, replaceable cutting elements installed on the gage pad allowing the cutting elements to engage the formation being drilled and to assist in providing gage-cutting, or side-cutting, action therealong. Replaceable cutters may also be placed adjacent to the gage area of the drill bit. One type of cutting element provided on or adjacent to gage pads in the past, referred to as inserts, compacts, and cutters, has been known and used for a relatively long time on the lower cutting face for providing the primary cutting action of the bit. These cutting elements are typically manufactured by forming a superabrasive layer, or table, upon a sintered tungsten carbide substrate. As an example, a polycrystalline diamond table, or cutting face, is sintered onto the sintered tungsten carbide substrate under high pressure and temperature, typically about 1450° to about 1600° Celsius and about 50 to about 70 kilo bar pressure to form a polycrystalline diamond compact (PDC) cutting element or PDC cutter. During this process, a metal sintering aid or catalyst such as cobalt may be premixed with the powdered diamond or swept from the substrate into the diamond to form a bonding matrix at the interface between the diamond and substrate.
The above-described PDC cutting elements, or cutters, when installed on or adjacent to gage pads instead of on the lower portion of the face of the drill bit, are generally referred to as “gage trimmers” as such a cutting element cuts the outermost gage dimension, or diameter, for the particular drill bit in which the cutters are installed. That is, the cutters, or more particularly the cutting surfaces thereof, being positioned at the furthermost radial distance from the longitudinal centerline of the drill bit, i.e., the outer periphery of the drill bit, will define the final diameter of the borehole being formed as a result of the drill bit engaging, cutting, and displacing the subterranean formation material in the forming of a well bore.
One particular situation that may damage gage trimmers is rotating the drill bit within a casing while a mud mixture or formulation is changed. For instance, mud formulation may be changed when moving from one type of subterranean formation to another in that oil-based mud formulations are typically preferred to water-based mud formulations when drilling shale. In the case of using downhole motors, the bit may necessarily rotate while the mud is changed because the flow of drilling fluid causes the downhole motor to rotate. Changing a drilling fluid (mud), as used herein, includes the addition of any additive or modifying a mud characteristic including: mud weight, pH, chemical composition, physical composition or viscosity.
Another condition where gage trimmers may be damaged may exist when a drill bit is “whirling.” Bit whirl is a complicated motion that includes many types of bit movement patterns or modes of motion wherein the bit typically does not rotate about its intended axis of rotation and may not remain centered within the borehole. Bit whirl may typically occur at relatively low weight-on-bit (WOB) coupled with relatively high rotational speed while drilling a borehole. Under either aforesaid conditions the gage trimmers may contact the side of the borehole or casing and be damaged. Therefore, there exists a need to protect gage trimmers under such conditions.
Prior art uses of tungsten carbide protective structures include various configurations on fixed cutter reamers and tricone bits. On tricone bits, ovoid sintered carbide protective structures have been used on the heel row of the cones. On fixed cutter reamers, ovoid sintered carbide protective structures have been used as described in U.S. Pat. No. 6,397,958, assigned assignee of the present invention, as being placed on the radially outer surface of a blade and facing generally radially outwardly, for example, on a rotationally trailing blade and/or on a rational leading blade, thus being circumferentially offset from a given blade, to provide an additional pass-through point to accommodate erratic rotational motion of the tool in the casing during drill out. Ovoid sintered tungsten carbide compacts may also be used sacrificially when drilling out the casing by being overexposed while drilling the casing.
U.S. Pat. No. 6,349,780 to Beuershausen, assigned to the assignee of the present invention, discloses a drill bit configured with gage pads of differing aggressiveness. In addition, Beuershausen also discloses that a drill bit may include gage-cutting elements of more than two levels or degrees of aggressivity.
U.S. Pat. No. 5,979,576 to Hansen et al., assigned to the assignee of the present invention, discloses that flank cutters with a depth of cut that is less than the “active cutting area” may be employed to reduce wear in the bearing zone of an antiwhirl bit. The flank cutters do not normally contact the borehole, except under certain drilling conditions such as reaming or high rates of penetration wherein whirl tendencies are not as pronounced. Hansen also teaches that natural diamond or diamond-impregnated studs may be placed in front of or behind the flank cutters to control the cutting forces generated adjacent the bearing zone.
U.S. Pat. No. 4,991,670 to Fuller et al. describes a plurality of protuberances impregnated with super hard particles that are positioned in a trailing relationship to a plurality of cutters.